Real-time system for hydraulic fracturing

ABSTRACT

A bottom hole assembly (BHA) located on a tubing string for use in a wellbore having an instrumentation sub and a mechanical fracturing/shifting tool for actuating sleeve valves located along the wellbore. The instrumentation sub is connected to surface via a wireline. Sensors can be located on the BHA for collecting data regarding parameters of the BHA and wellbore and transmitting the data to surface in real-time or near real-time. The instrumentation sub can have an electrical throughput to permit electrical components to be connected downhole of the instrumentation sub. A short-hop system can bridge communication of data above and below the mechanical shifting tool, such that measurements of sensors downhole of the shifting tool can be wirelessly transmitted to the instrumentation sub uphole of the shifting tool. Dimensions of a bore of the BHA can be selected to permit fluid flow at fracturing rates.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application62/943,676, filed Dec. 4, 2019, the entirety of which is incorporatedfully herein by reference.

FIELD

Embodiments herein relate to methods and apparatus used for completionof a wellbore and, more particularly, to methods for performingcompletion operations and monitoring in real-time, at surface, downholeconditions during completion operations.

BACKGROUND

Apparatus and methods are known for single-trip completions of deviatedwellbores, such as horizontal wellbores. To date, unlike the drillingindustry which commonly utilizes intelligent apparatus for drillingwellbores, particularly horizontal or deviated wellbores, the fracturingindustry has relied largely on mechanically-actuated apparatus toperform a majority of the operations required to complete a wellbore.This is particularly the case with coiled tubing (CT) deployed bottomhole assemblies (BHA's), largely due to the difficulty in providingsufficient, reliable electrical signals and power from surface to theBHA and vice versa. Further, fracturing operations require relativelyhigh flow rates through the CT, in the order of about 1 m³/min orgreater. The bore restrictions necessitated by the inclusion ofelectronic equipment on existing instrumentation subs, such as thoseused in drilling operations, limits flow rates therethrough to an extentthat is not conducive for fracturing operations.

It is known to deploy BHAs for completion operations using jointedtubular, wireline or cable, or coiled tubing (CT). Further, it is knownto use wireline deployed within an interior of CT to electricallyactuate conventional select-fire perforation charges and to transmitsignals associated with casing-collar locators used in depthmeasurement, such as taught in U.S. Pat. No. 7,059,407 to Toman.

One class of prior methodology for performing fracturing operations iscommonly referred to as “plug and perf”. Fracturing operations atmultiple zones in a formation have used wireline-deployedelectrically-actuated bridge plugs which are pumped into the wellbore.The known pump-down bridge plugs have a single, fixed diameter beingslightly smaller than the wellbore for deployment into the wellbore andrequire a valve at a toe of the wellbore to remove fluid used to pumpthe bridge plug into place. As wireline is comparatively weak and cannotpull more than about 2500 lbs at surface, and much less at depth, thewireline cannot be reliably used to release or to pull the bridge plugsto surface. Thus, multiple bridge plugs must be used and left in thewellbore to be drilled out later, at considerable expense. After thebridge plug has been set, the casing is perforated with perforating gunslocated above the bridge plug. The bridge plug and the perforating gunsare often deployed together so that both operations, isolating andperforating, can be done in the same wireline run. When the perforationshave been shot, the wireline is pulled out of the hole and the fracturefluid is pumped through the casing. Once the fracture is completed, thesteps of setting the bridge plug and perforating followed by pumping thefrac are repeated for sequential uphole intervals until the fracturingjob on the wellbore is complete. Following fracturing of all of thezones, the bridge plugs are drilled out.

In other embodiments, a plurality of sliding sleeve subs, each subhaving pre-existing fracturing ports, are spaced along a casing stringor a liner of a wellbore and located at zones of interest in theformation. The sliding sleeves of the sleeve subs are selectively openedto expose the pre-existing fracturing ports, minimizing the need toperforate the casing to access the formation therebeyond. In some cases,the sleeves can also be actuated back to a closed position for isolatingportions of the formation from fluids flowing through the casing, suchas when fracturing through the ports of other sleeves, or to permit thezone of the formation to “heal”. The sleeve subs can be opened using avariety of conventional sleeve opening and closing techniques,including, but not limited to, setting a packer of a BHA within thesleeve, expanding the packer element, and thereafter utilizing a tensilepull for or fluid flow in the annulus to force the first packer andsleeve to shift the sleeve axially therein. Other sleeve actuationtechniques involve electronically or mechanically actuating a shiftingtool incorporated in a BHA installed on CT to engage and axially shiftthe sleeve, or by actuating a rotational opening tool to engage androtate the sleeve to an open position. Alternatively, differentialpressure can be used to hydraulically open the sleeve.

In fracturing operations using sleeve subs, a shifting tool is run inhole, typically on CT having a BHA at a distal end that is fit with theshifting tool. The CT is run into the wellbore and the shifting tool isused to selectively engage and actuate the sliding sleeves to establishor shut off communication between the wellbore and the various zones inthe formation. Once the shifting tool has engaged a target sleeve, theCT is manipulated to selectively open the sleeve and expose thefracturing ports at said sleeve. A packer set below the fracturing portsdirects fracturing fluid to exit the wellbore through open portsthereabove. In embodiments, the shifting tool can also close selectedsleeves, such as to permit the formation to heal, or enable fracturingthrough opened ports in other sleeves therebelow. Treatment fluid can bedelivered to the selected zone of the formation through the annulusbetween the casing and the CT, through the CT, or through both at thesame time. Typical sleeve-shifting BHA's comprise mechanically-operateddownhole tools having telescoping mandrels, packers and tubing,controlled by axially delimited J-mechanisms for selecting a variety ofoperating modes of the shifting tool. While reliable, the axiallyreciprocating components of the shifting tool introduce challenges asdescribed below.

As will be appreciated by those of skill in the art, the acquisition ofdownhole conditions before, during, and after fracturing is performed isuseful to operators. Multi-zone fracturing is characterized by setting apacker and introduction of proppant-loaded treatment fluid at highpressure to a zone or stage, then repeated release, pressureequalization, and re-location of the BHA to subsequent fracturingstages. Downhole conditions are determined with electronic sensors andthe data is typically stored in memory located in tools carried by theBHA. In conventional methods, the data pertaining to downhole conditionsis stored in memory and reviewed at surface after the BHA is pulled outof hole. A disadvantage of storing sensor data to on-board memory isthat the downhole conditions are not known until such operations arecompleted and the BHA has been retrieved to surface. As such, theoperator cannot adjust the operating parameters of the BHA andfracturing operation to respond to changes in downhole conditions asthey arise in real-time, or near real-time.

Real-time tools have been applied in drilling operations and the like.Downhole parameters related to the downhole drilling environment andparameters are not directly ascertainable at surface. As such, theoperator is typically only provided with surface feedback, such astorque and string weight variation to estimate downhole performance.Absent direct downhole data, which may be located thousands of metersdistant from surface, too much or too little string weight can beapplied at surface, resulting in downhole tool damage or ineffectiverate of penetration. Accordingly, coiled-tubing conveyed BHAs capable ofacquiring direct, real-time downhole data and delivering said data tosurface may be used, such as that disclosed in published internationalapplication WO 2018/137027 to Timberstone Tools Inc, Canada,incorporated herein in its entirety. An electrically enabled coiledtubing, such as coiled tubing having wireline running therethrough orfixed to the inner or outer walls thereof, forms a non-rotatingconveyance string and can conduct data readings uphole during drilling.The BHA is fit with a variety of sensors, including those capable ofmeasuring pressure and acceleration, for gathering downhole parametersrelating to the drilling interface. Such real-time communication systemsbetween surface and drilling BHAs are robust in part due to the fixedarrangement of the coiled tubing, which has no moving parts. However,repetitive movement of the coiled tubing and wireline can result infatigue connection issues. Thus, these applications are suitable for usewith fixed assemblies of components which are not subject to repeatedmovement, and no relative movement therealong, such as with telescopingof a portion of the BHA.

In hydraulic fracturing operations, the sleeve shifting tool of a BHA issubject to repeated, relative axial movement to set the packer and cyclethe J-mechanism, and is subject to high fluid rates of abrasive,proppant loaded fluids flowing therethrough and thereby in the annulusbetween the BHA and wellbore. Such operating conditions are unsuitablefor the implementation of real-time instrumentation subs, such as thoseused for drilling operations, due to fatigue issues caused by therepeated relative axial movement of the shifting tool. It isparticularly difficult to locate sensors on the BHA below the shiftingtool, as the telescoping and/or rotational movement of portions of theshifting tool relative to the coiled tubing presents a significantobstacle to electrically connecting sensors below the shifting tool toan instrumentation sub or other electrical components thereabove.

Additionally, present instrumentation subs for drilling have restrictedinner bore diameters due to the space requirements for housing andsealing circuits and other electronic components therein. Flow is alsorestricted at the cable head assembly of the instrumentation sub, wherethe electrical connections in a wireline cable terminate and areconnected to contacts of the instrumentation sub. Such restricted borediameters result in relatively lower fluid flow rates therethrough thatare not conducive to fracturing operations, which typically require flowrates of 1 m³/min or greater. In fracturing operations, it is preferableto have unrestricted flow capacity throughout the CT, and not berestricted at any point, such as at the instrumentation sub of the BHA.Such flow restriction at the BHA can also result in severe erosion, dueto the high flow rates required for fracturing operations, and the factthat fracturing fluid is often sand-laden and quite erosive. As cleanfluid is typically used in drilling operations, and flow rates arelower, conventional instrumentation subs for drilling operations are notdesigned to account for the flow and erosion considerations offracturing operations and are therefore unsuitable for use in suchoperations

Further, conventional instrumentation subs for drilling do not havemeans for communicating with components below the BHA, such asadditional sensors. Information acquired by such sensors may be usefulin fracturing operations. For example, downhole pressure data above andbelow the packer of the BHA can be used to determine whether the packerwas successfully set before fracturing fluid is pumped into thewellbore.

There is interest in the industry to improve access to operational dataat the downhole tool for improving reliability and effectiveness ofhydraulic fracturing.

SUMMARY

Embodiments of a bottom hole assembly (BHA) are provided herein forobtaining data regarding downhole conditions and BHA operation duringfracturing operations, and transmitting said data in real-time from theBHA to surface. Some embodiments also permit bi-directionalcommunication between the BHA and surface, such that instructions can besent from surface or remotely to the BHA. The BHA is connected to thedownhole or distal end of coiled tubing (CT) or a similar tubularstring.

The monitoring of pressure uphole and downhole of a BHA duringfracturing operations provides data indicative of how the formation isreacting to the fracturing operation and may also be indicative of theintegrity of the isolation effectiveness of the BHA and thecharacteristics of the formation between adjacent zones. Instead ofcalculating or estimating downhole parameters from parameters measurableat surface, or reviewing data at a later time as recovered frommachine-readable memory located on the BHA, downhole data is transmittedto surface in real-time or near real-time.

In one embodiment, real-time downhole data collection and transmissionis effected, including on mechanical BHA tools, using an electronicsinterface sub located on the conveyance string.

In some embodiments, a short-hop wireless transmission system can beimplemented to permit communication between components uphole anddownhole from the mechanical BHA tool.

In another embodiment, real-time or near real-time downhole datacollection and transmission is effected uphole and downhole of anelectronically-actuated BHA tool, the uphole and downhole being axiallyfixed.

In embodiments, abrasive fracturing fluid is delivered through theannulus for minimizing erosive effects on the electronics interface sub.The annulus provides a large cross-sectional area suitable for the highfluid rates required for hydraulic fracturing. Fracturing fluid can alsobe communicated downhole via the bore of the CT. The electronicsinterface sub can be configured to provide an axial bore that permitsflow rates suitable for fracturing operations, and avoid flow borerestrictions that would result in accelerated erosion due to fracturingfluid flowing therethrough. Further, when treatment fluid is deliveredto the formation through one of the annulus and the CT, the other canact as a “dead leg”. For example, when the treatment fluid is deliveredthrough the annulus, a minimal, constant amount of a deadhead fluid canbe delivered through the tubing string to act as the “dead leg” formaintaining pressure within the CT. The pressure required to maintainthe constant fluid delivery is monitored from surface and can be usedfor calculating fracture extension pressure and formation breakdownpressure, as well as fracture closure pressure.

In conventional completion operations, a “dead leg” is used not only toprevent collapse of the CT under pressure from fluids in the annulus,but also to permit calculation of pressure to determine reaction of theformation to the fracturing operation.

However, in embodiments where the CT is electronically enabled coilhaving a wireline running therethrough, and the bore of CT is fluidlycoupled with the annulus, such as through ports at the BHA, flow ofabrasive fluid downhole or uphole through the CT is discouraged due topotential erosion of the electronic interface sub, and the wirelineitself. There is the possibility of reverse flow into the CT, bypressure imbalance or through operator directed purposeful reversecirculation to clear sands from the packer area and the like.

As introduced above, mechanical fracturing tools incorporate axiallytelescoping components, such as to compress a packer, complicatingelectrical connections uphole to downhole of the packer.

As discussed in Applicant's international application WO/2013/159237,published Oct. 31, 2013, and incorporated herein in its entirety,electrically-enabled CT was implemented for bidirectional communicationof signals between a BHA and surface. Power can be provided to the BHAcomponents which can be electrically-actuated. The disclosed BHAcomprised an electrically-actuated, variable diameter packer locatedbelow fracturing treatment ports. The electrically-enabled BHA obviatesthe need for axially movable components and includes electricalcircuitry extending below the packer to arrays of perforating gunstherebelow.

Herein, a downhole fracturing tool is provided comprising electricallyenabled coiled tubing, an interface sub and a mechanically-actuated BHA.

In a general aspect, a bottom hole assembly (BHA) adapted for connectionto coiled tubing extending from surface into a wellbore is provided, thecoiled tubing having a tubing bore, the BHA comprising: aninstrumentation sub in electrical communication with the surface andhaving a data processor, an axial bore in communication with the tubingbore, and an electrical conduit permitting electrical power and signalsto pass from a first end of the instrumentation sub to a second end ofthe instrumentation sub downhole of the first end; one or more sensorselectrically connected to the instrumentation sub; and a mechanicalshifting tool downhole of the instrumentation sub and adapted foractuating sleeve valves located along the wellbore; wherein the dataprocessor is adapted to receive data from the one or more sensors andcommunicate the data to the surface; and wherein the axial bore is sizedto permit a fluid flow rate conducive to hydraulic fracturingoperations.

In an embodiment, the one or more sensors comprise at least one of a 3Ddirectional sensor, a sensor adapted to determine axial movement, asensor adapted to determine rotational movement, an axial force sensor,an accelerometer, a positional sensor, a pressure sensor, a temperaturesensor, or a combination thereof.

In an embodiment, the BHA further comprises a receiver located uphole ofthe shifting tool and a transmitter located downhole of the shiftingtool, wherein the transmitter is electrically connected to one or moreelectrical components located downhole of the shifting tool and thereceiver is electrically connected to the data processor, and whereinthe transmitter is adapted to communicate data to the receiver.

In an embodiment, the receiver is a first transceiver, and thetransmitter is a second transceiver.

In an embodiment, at least one of the one or more sensors is locateddownhole of the shifting tool and electrically connected to thetransmitter.

In an embodiment, at least a first pressure sensor is located uphole ofthe shifting tool and at least a second pressure sensor is locateddownhole of the shifting tool and electrically connected to thetransmitter.

In an embodiment, the BHA further comprises a check valve locatedin-line with the axial bore and adapted to prevent fluid from flowinguphole therethrough.

In an embodiment, the fluid flow rate is about 1 m3/min or greater.

In an embodiment, the BHA further comprises a power source and memorymodule located on the instrumentation sub and electrically connected tothe one or more sensors.

In an embodiment, the shifting tool is configured to actuate betweenvarious operational modes via an axial telescopic movement of a mandrelof the shifting tool relative to a housing of the shifting tool.

In an embodiment, the BHA further comprises a disconnect located betweenthe instrumentation sub and the shifting tool.

In an embodiment, the disconnect is configured to sever an electricaland mechanical connection between the instrumentation sub and shiftingtool in response to an electrical signal.

In an embodiment, the disconnect is configured to sever an electricaland mechanical connection between the instrumentation sub and shiftingtool in response to an actuating member engaging the disconnect.

In an embodiment, the diameter of the axial bore is substantiallyuniform.

In an embodiment, the BHA further comprises a drilling tool adapted tobe interchangeable with the shifting tool.

In a general embodiment, a method for performing fracturing operationsin a wellbore having one or more sleeve valves positioned therealongcomprises: running a bottom hole assembly (BHA) located on a tubingstring to a position adjacent a sleeve valve of interest of the one ormore sleeve valves; pulling uphole on the BHA to locate the sleeve valveof interest using a mechanical shifting tool of the BHA; acquiring dataregarding one or more parameters of the BHA and wellbore using one ormore sensors electrically connected to an instrumentation sub of theBHA; confirming the successful locating of the sleeve valve of interestusing the acquired data; actuating the sleeve valve of interest to anopen position with the shifting tool; isolating the wellbore below thesleeve valve of interest with a packer of the BHA; and introducing fluidinto the wellbore to fracture a zone of interest of the wellboreadjacent the sleeve valve of interest.

In an embodiment, the method further comprises confirming the successfulactuation of the sleeve valve of interest to the open position using theacquired data, and wherein the acquired data comprises at least one ofaccelerometer data and axial load data.

In an embodiment, the method further comprises confirming the successfulisolation of the wellbore below the sleeve valve of interest using theacquired data, and wherein the acquired data comprises at least dataregarding a first pressure uphole of the shifting tool and dataregarding a second pressure downhole of the shifting tool.

In an embodiment, the step of acquiring data further comprises acquiringthe second pressure using a pressure sensor downhole of the shiftingtool, receiving the data regarding the second pressure at a transmitterdownhole of the shifting tool, and sending the data regarding the secondpressure to a receiver uphole of the shifting tool.

In an embodiment, the acquired data comprises data regarding pressurewithin an axial bore of the BHA and pressure within an annulus definedbetween the BHA and the wellbore, and the step of introducing fluidfurther comprises monitoring the pressure in the axial bore and thepressure in the annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative illustration of a downhole fracturingoperation incorporating an instrumentation sub in a bottom hole assemblyfor communicating data regarding various downhole parameters to surface;

FIG. 2A is a representative illustration of an embodiment of a bottomhole assembly having an instrumentation sub incorporated therein foracquiring data regarding various downhole parameters;

FIG. 2B is a representative illustration of another embodiment of abottom hole assembly having an instrumentation sub;

FIG. 3A is a cross-sectional depiction of another embodiment of a bottomhole assembly incorporating an instrumentation sub, according to anembodiment of the disclosure;

FIG. 3B is a cross-sectional depiction of the bottom hole assembly ofFIG. 3A in use for shifting a sleeve located along a wellbore andfracturing a zone of interest outside and adjacent to the sleeve;

FIG. 4A is an elevation view of an embodiment of an instrumentation subfor use with a bottom hole assembly for fracturing operations; and

FIG. 4B is a cross-sectional view of the instrumentation sub of FIG. 4A.

DETAILED DESCRIPTION

Embodiments are described herein in the context of fracturingoperations. However, as one of skill in the art will understand, systemsand methods disclosed herein are also applicable to other completion andstimulation operations.

The terms “uphole” and “downhole” used herein are applicable regardlessthe type of wellbore; “downhole” indicating being toward a distal end ortoe of the wellbore and “uphole” indicating being toward a proximal endor surface of the wellbore.

With reference to FIG. 1, embodiments described herein utilize anelectronic instrumentation sub and electronic sensing componentsincorporated into a bottom-hole assembly (BHA) having amechanically-actuated fracturing/sleeve shifting tool. The BHA can berun into a wellbore on a tubing string, such as coiled tubing (CT), forcompletion of multiple zones of interest of a hydrocarbon formationadjacent to the wellbore. The electronic instrumentation sub can beconnected to monitoring equipment at surface, such as via a wirelinerunning through, fixed to, or embedded in coiled tubing forcommunicating data collected by the sensing components regarding variouswellbore parameters to surface. The CT and wireline can be provided on aspool connected to a motor. Moreover, a bore of the instrumentation subis configured to accommodate the flow requirements of fracturingoperations and be suitable for use with the flow rates and erosivefluids often utilized in such operations. Incorporation of theinstrumentation sub and electronic sensing equipment in conjunction witha mechanical fracturing tool enables operators to be aware of downholeconditions and make adjustments to completion operations in real-time ornear real-time, thus permitting flexibility heretofore unavailable inconventional completion operations using mechanically-actuatedfracturing/shifting tools alone. A pump at surface is configured to pumpfracturing fluid, such as a sand-laden fluid, downhole via the bore ofthe CT or the annulus formed between the CT and wellbore casing.

Embodiments described herein are useful for treating or fracturing newwellbores that are drilled, but have not yet been completed. Thewellbores can be cased and have ported sliding sleeve subs installedtherein, the sleeve subs having sliding sleeves actuable between aclosed position, wherein the sleeves cover fracturing ports of thesleeve sub, and an open position, wherein the fracturing ports areexposed to establish fluid communication between the wellbore and theformation. At the beginning of fracturing operations, the sleeves aretypically in the closed position, having not yet been actuated to exposethe fracturing ports. In embodiments, the sliding sleeves may also beselectively closable to stop communication between the formation and thewellbore therethrough. The sliding sleeves can have an inner profileadapted to be engaged by the fracturing tool of the BHA such that thesleeves can be shifted axially between the open and closed positions bymanipulation of the CT after being engaged by the fracturing tool.

General BHA Construction

In embodiments, with reference to FIGS. 2A and 2B, a BHA is shownlocated at a distal end of a CT string for deployment into a wellborefor completion operations, such as fracturing operations. The BHAcomprises an instrumentation sub, a mechanically actuatedfracturing/sleeve shifting tool, and one or more sensors electricallyconnected to the instrumentation sub and capable of measuring variousparameters of the BHA and wellbore. The sensors can be configured tomeasure parameters such as circulation pressure inside the CT, wellborepressure in the annulus surrounding the CT and BHA, differentialpressure across select components (e.g. across a packer of thefracturing tool), relative axial force on the CT (e.g. tension andcompression), BHA vibration or shock (e.g. total RMS vibration), torque,BHA inclination, axial and/or rotational movement of the BHA, and 3Ddirection of the BHA. In the depicted embodiments, the mechanicalfracturing tool is located downhole from the instrumentation sub. Inalternative embodiments, the fracturing tool can be located uphole fromthe instrumentation sub.

When the BHA is deployed into the wellbore, an annulus is formed betweenthe CT/BHA and the wellbore casing. Fluid can be conducted from surfacedownhole through a tubing bore of the CT, or through the annulus. TheBHA can also have an axial bore for allowing the communication of fluidtherethrough. Bi-directional electrical communication between surfaceand the BHA is enabled via wireline. The wireline is connected at aproximal end thereof to electrical equipment at surface, such as acontroller and a display device, and terminates at a distal end thereofat a cable head assembly of the instrumentation sub. As one of skill inthe art will understand, any wireline or other electrical connectionthat provides sufficient electrical capability to permit transmission ofpower and communication of data between the BHA and surface would besuitable for use in embodiments described herein. In embodiments, fiberoptics incorporated into the wireline may be used to communicate databetween surface and the BHA.

In embodiments, a release sub or disconnect can be located between theinstrumentation sub and the fracturing tool, such that theinstrumentation sub can be disconnected from the fracturing tool andretrieved to surface in the event the fracturing tool becomes stuck inthe wellbore. The disconnect can be mechanically actuated, such as via aball or other actuating member dropped into the CT from surface toengage the disconnect, or electrically connected to the instrumentationsub and electrically actuated to decouple the fracturing tool from thecomponents thereabove. In other embodiments, the disconnect can beconfigured to separate if a predetermined tensile load is experienced.

The BHA is fluidly connected to a distal end of the CT, and theinstrumentation sub has an axial bore having a cross-sectional flow areathat permits fluid flow rates suitable for fracturing operations whileavoiding fluid velocities that would result in severe erosion of theaxial bore due to fracturing fluid flowing therethrough. Additionally,the cable head assembly of the instrumentation sub is configured suchthat it does not restrict the size of the axial bore of the sub, furtherenabling fluid flow rates required for fracturing operations, andmitigating erosion of components in the instrumentation sub. Such anenlarged flow area is advantageous over prior art instrumentation subs,which have restricted axial bores in order to accommodate electroniccomponents in a bulkhead of the sub.

In embodiments, the axial bore of the instrumentation sub is deviated toaccommodate the electronic components of the instrumentation sub. Thelocation at which the axial bore deviates is particularly susceptible toerosion. To mitigate such erosive effects, the angle at which the axialbore is deviated can be reduced.

At least one radially-extending fracturing port can be formed in thehousing of the BHA and be configured to selectively permit fluidcommunication between the axial bore and annulus such that fracturingfluid can be delivered to the formation via the tubing bore and axialbore in coiled-tubing fracturing operations. In the embodiment depictedin FIGS. 2A and 2B, the fracturing ports are located downhole from theinstrumentation sub, between the disconnect and the fracturing tool.

In embodiments, the instrumentation sub can have a power storage means,such as a battery or capacitor, and a memory module configured to storedata acquired by sensors, and be capable of operating in a memory modein which data collected by the sensors is stored in the memory modulefor later retrieval. In embodiments, the instrumentation sub can operatein the memory mode while transmitting downhole data to surface, suchthat a backup of the data is stored in the event real-time datatransmission to surface is interrupted or otherwise unavailable.

Fracturing Tool

In embodiments, the fracturing tool is a mechanical sleeve shifting toolsuch as that shown in FIGS. 2A-3B, comprising a packer, a plurality ofdogs, and a J-slot mechanism that enables the tool to be actuatedbetween various operating modes, including a running position (RIH), asleeve locating position (LOCATE), a set or sleeve engaged position(SET), and a pull-out-of-hole position (POOH). The dogs have uphole anddownhole interfaces configured to engage with the sleeve profiles of thesleeve valves located along the wellbore casing. In the running positionRIH and pull-out-of-hole position POOH, the plurality of dogs are in aradially inwardly retracted position such that the dogs do not contactor engage the wellbore casing or sleeves as the tool is beingrun-in-hole RIH or pulled-out-of-hole POOH. In the sleeve locatingposition LOCATE, the dogs are biased radially outwards into contact withthe wellbore casing and the sleeve valves, such that the dogs willengage the sleeve profiles of the sleeve valves as the BHA is axiallymanipulated thereby. In the sleeve engaged position SET, the dogs arelocked in the radially outward position in engagement with the sleeveprofile of a sleeve, such as by a cone, such that the tool can be RIH orPOOH to open or close the sleeve valve. Further, in the SET position,the packer of the fracturing tool is energized and engaged with thewellbore to isolate the portion of the wellbore above the fracturingtool from the portion of the wellbore therebelow. In embodiments, abypass valve of the fracturing tool is also closed to prevent fluid fromflowing downhole of the fracturing tool through the axial bore of theBHA.

A best shown in FIGS. 3A and 3B, the dogs can be secured to a housing ofthe fractural tool while the packer and cone can be secured to afracturing tool mandrel. Mandrel is telescopically connected to thefracturing tool housing such that axial manipulation of the CTtelescopically actuates the mandrel relative to the fracturing toolhousing. A drag sub or drag block can be connected to the housing toprovide axial resistance and facilitate the telescoping action of themandrel. The various operating modes of the BHA are delimited by theJ-slot mechanism and are correlated to the axial position of the mandrelrelative to the fracturing tool housing. For example, the dogs can belocated at the distal ends of arms having cams formed thereon, the camshaving a radially varying profile. An actuating ring or spider securedto, and movable with, the mandrel is configured to engage the cams ofthe arms and retract the arms and dogs radially inwardly or permit thearms and dogs to extend radially outwardly, depending on the axialposition of the mandrel relative to the housing. Axial stroking of themandrel relative to the housing cycles the J-slot mechanism and actuatesthe fracturing tool through its operating modes. As discussed above,such axial telescoping makes it difficult to locate sensors and otherelectrical components downhole of the fracturing tool, as providing anelectrical connection between the uphole and downhole ends of thefracturing tool is challenging due to the varying axial distancetherebetween.

An example of a suitable fracturing/shifting tool for use with the BHAis the tool disclosed in Applicant's U.S. Pat. No. 10,472,928,incorporated herein in its entirety. One of skill in the art wouldunderstand that other fracturing tools may be used depending on factorssuch as the type of sleeve or zone isolation mechanism used in thewellbore.

Short Hop System

In embodiments, with reference again to FIGS. 2A and 2B, a receiver canbe located uphole from the fracturing tool, such as inside theinstrumentation sub or in a separate receiver sub electrically connectedto the instrumentation sub, and a transmitter can be located downholefrom the fracturing tool, such as on a transmitter sub. The transmittercan be connected to sensors configured to take measurements of variousparameters downhole of the fracturing tool, such as annular pressure,temperature, tension/compression, and torque, and wirelessly send saidmeasurements or other data to the receiver for subsequent transmissionto surface in real-time or near real-time. Such a “short hop” system forbridging communication of data above and below the fracturing tool isdesirable. For example, sensors can be used to obtain pressure dataabove and below packers or other isolation elements of the fracturingtool in order to confirm whether the packer was successfully engagedagainst the casing to isolate the zone of interest from the rest of thewellbore before fracturing. In embodiments, first and secondtransceivers can be used in place of the receiver and transmitter, suchthat data can be communicated bi-directionally between components upholeand downhole of the fracturing tool.

Currently, data regarding the uphole and downhole ends of the fracturingtool is collected by sensors and stored in memory modules onboard theBHA to be analyzed at surface when the BHA is retrieved. Real-timecommunication of such data to surface has been heretofore unavailabledue to the difficulty of establishing a physical electrical connectionbetween equipment uphole and downhole of the mechanical fracturing toolas a result of the axially reciprocating and rotational functions of thetool.

The transmitter/transceiver downhole of the fracturing tool can bepowered by an on-board power source located on the BHA downhole of thefracturing tool, such as a battery or a capacitor, such that it isunnecessary to have any electrical connection between the uphole anddownhole ends of the fracturing tool.

Electrical Throughput

The instrumentation sub can have an electrical throughput to permitadditional electrical tools to be located below the instrumentation sub.Electrical connection between the instrumentation sub and componentstherebelow can be accomplished in a number of ways including, but notlimited to, conductors extending therebetween through the axial bore ofthe BHA, or conductors extending therebetween through an electrical raceformed about a periphery of the BHA's components.

Check Valve

In embodiments, a check valve is located in the axial bore of the BHA toprevent fluids from flowing from the wellbore up the CT and potentiallydamaging the wireline. The check valve can comprise a mechanical checkvalve or an electrically-actuated valve, such as a solenoid valve. Asbest seen in FIGS. 2A, 2B, and 4B, the check valve is located in theaxial bore of the BHA downhole from the instrumentation sub, such thatfluid cannot flow uphole from the wellbore to the tubing bore of the CTthrough the instrumentation sub and potentially damage the components orconnections therein. An issue with check valves currently employed inBHAs is that they have relatively restricted bore dimensions, resultingin reduced flow rates therethrough that may not be conducive tofracturing operations, and suffering damage as the erosive wellborefluids flow therethrough. The check valve of the present application hasa bore sized to permit fluid flow rates suitable for fracturingoperations. For example, the check valve bore can be sized to permit aflow rate of at least 1 m³/min therethrough.

Sensors & Controller

As discussed above, the sleeve shifting/fracturing tool of the BHA isused to open and close sleeves by actuating the shifting tool to engagethe sleeve profile of the sleeve sub of the zone of interest and pullingthe CT uphole or running it downhole to axially shift the sleeve.Currently, mechanical shifting tools do not have means to confirmwhether the shifting tool has successfully engaged with the sleeveprofile of the desired sleeve, whether the sleeve was successfullyshifted, and whether the packer of the BHA has successfully sealed withthe wellbore casing in preparation for fracturing operations.

To provide such downhole measurement capabilities, the BHA can be fitwith one or more sensors to measure parameters of interest duringfracturing operations. The one or more sensors can be electricallyconnected to the instrumentation sub, which is configured to receive thedata measured by the sensors and communicate it to surface in real-timeor near real-time via the wireline.

A terminal can be located at surface to receive the data transmitted bythe instrumentation sub. The terminal can have or otherwise be connectedto a display device and be configured to display the received data onthe display device. In embodiments, the terminal can also act as acontroller capable of sending commands to the BHA and configured tomanage various fracturing operation parameters, such as a rate ofinjection of fluid into the wellbore, axial or rotational force appliedto the CT string, whether to open or close the electronic check valve orrelease the electronic disconnect, and other parameters. In embodiments,as shown in FIG. 1, the terminal can further be configured to compilethe data into charts or tables, or process the data into other forms forfurther analysis.

In embodiments, the terminal can have a wireless communications moduleto enable the data received from the instrumentation sub to betransmitted over a wireless network, such as the Internet, a cellularnetwork, and the like. Instructions to the BHA can also be sent over thewireless network to the terminal to be relayed to the BHA.

In embodiments described herein, and having reference again to FIGS. 2Aand 2B, the instrumentation sub of the BHA and the sensors connectedthereto permit direct measurement of parameters such as pressure,temperature, strain, vibration and the like, and the transmission of theacquired data to surface in real-time or near real-time.

One or more of the sensors can be a strain sensor configured to measureaxial loading of the CT string and/or the BHA to assist the operator tounderstand if the CT string or BHA is under tension or compression,which can be useful in determining whether the fracturing tool hasengaged a sleeve profile while in the sleeve locating position, orwhether the packer of the fracturing tool has successfully engaged withthe casing. In embodiments, the strain sensor is located in theinstrumentation sub above the fracturing tool. As one of skill in theart will appreciate, the strain gauges or sensors provide data tosurface to assist with determining the status of the fracturing tool andwhether an operator can proceed to the next stage of the fracturingoperation.

In an embodiment, one or more strain sensors can also be locateddownhole from the fracturing tool and connected to the short hoptransmitter/transceiver for measuring tension and compression below thetool and transmitting the measured data to surface. In such embodiments,the strain sensor(s) are preferably located uphole from the drag sub ofthe BHA so as to obtain accurate strain measurements.

The sensors can also comprise position sensors, such as accelerometersor MEMS sensors, which are capable of measuring and providing dataregarding the orientation of each of the sensors. The data from thesensors are then mathematically manipulated with respect to theorientation of the sensors to determine the position, orientation, andbearing of the BHA, as is understood in the art. The accelerometers canbe placed on multiple axes to determine movement, direction, andorientation of the BHA as well as to detect vibration and shocks to theBHA, for example when the dogs of the fracturing tool engaged the sleeveprofile of a sleeve and movement of the BHA stops abruptly.

Temperature sensors can also be located on the BHA to measure fluid andwellbore temperatures.

Pressure sensors can also be used in the BHA at different locations todetermine the differential pressure, for example on either side of thepacker of the fracturing tool when it is deployed. Such differentialpressure measurements can be used to determine whether the packersuccessfully has engaged the casing to isolate the zone of interest forfracturing. Pressure sensors can also be located inside and outside theCT for determining pressures in the annulus and/or CT tubing bore, aswell as the differential pressure therebetween. As will be appreciatedby those of skill in the art, pressure P1 above the packer of thefracturing tool is indicative of how the formation is reacting to thefracturing operation while pressure P2 below the packer may beindicative of the integrity of the packer element the packer and theformation between adjacent zones. Further, after cessation of pumping ofthe fracture fluid into the wellbore, fracture closure pressures canalso be monitored. The ability to measure pressure may be particularlyadvantageous when high rate foam fracturing is performed as measuringpressure enables understanding of the quality of the foam at theperforations. As discussed above, the implementation of short-hop subsabove and below the fracturing tool permit the use of pressure sensorsabove and below the fracturing tool for measuring P1 and P2, and thetransmission of data acquired therewith to surface in real-time, whileavoiding the problems associated with electrically connecting the upholeand downhole ends of the telescoping fracturing tool.

Movement sensors such as accelerometers can also be provided on the BHAfor measuring axial or rotational movement thereof. Such sensors canhave a resolution sufficient to measure small axial movements, such thataxial movement of the BHA when shifting a sleeve between the open andclosed positions can be detected by the sensors to confirm successfulshifting of the sleeve.

The inclusion of sensors capable of providing 3D survey and inclinationdata is also advantageous, at it permits the BHA to be quicklyreconfigured for drilling and fracturing operations. For example, adrilling tool can be attached to the BHA, such as at the disconnect, andused to drill a wellbore. The positioning sensors on the instrumentationsub are used to provide real-time data regarding the drilling operation.Once drilling is complete, the BHA can be retrieved to surface, and thedrilling tool can be removed therefrom. A fracturing tool can then beconnected to the BHA, for example at the disconnect, and the BHA usedfor fracturing operations.

Additionally, the one of more sensors can also comprise 3D directionalsensors, which could be used in embodiments where the BHA is used todirectionally drill a wellbore.

In embodiments, sensors specific to the drilling operation can belocated on or downhole of the drilling tool, and sensors specific to thefracturing operation can be located on or downhole of thefracturing/shifting tool.

As one of skill in the art would understand, additional sensors formeasuring other parameters of the BHA and wellbore can be provided onthe BHA in order to provide additional data during fracturingoperations.

Use in New Cased or Lined Wellbores

In use, as shown in FIG. 1, the BHA is connected to the distal end of aCT string and is run into the wellbore. The wellbore has a plurality ofsleeve subs positioned adjacent various zones of interest of thewellbore. The instrumentation sub of the BHA is electrically connectedto the distal end of a wireline. A proximal or surface end of thewireline is connected to the terminal and other equipment at surfaceconfigured to receive data from the instrumentation sub and sendinstructions to the BHA and surface equipment for controlling variousaspects of the fracturing operation. Typically, the BHA is first run tothe toe of the wellbore as fracturing is performed at intervals or zonesof interest from the toe of the wellbore toward a heel of the wellbore.

The fracturing tool of the BHA can first be set to the running positionand run-in-hole to the toe of the wellbore. After reaching the toe, thefracturing tool can then be actuated to the sleeve locating positionLOCATE and pulled uphole until it reaches the first zone of interest andengages the sleeve profile of a corresponding sleeve valve of interest.Arrival of the BHA at the first zone of interest can be confirmed bydata received from the various sensors of the BHA, as described above.For example, confirmation that the fracturing tool successfully hasengaged the sleeve profile of the sleeve sub of the first zone ofinterest can be obtained from data acquired by the strain gauges andaccelerometers, which would respectively show increased tension alongthe CT string and a sudden deceleration.

Once engagement with the sleeve profile by the fracturing tool isconfirmed, the tool can be actuated to the sleeve engaged position SETto lock the dogs of the fracturing tool in engagement with the sleeveprofile, and the BHA can be lowered downhole to shift the sleeve to theopen position and expose the fracturing ports of the sleeve sub, therebyestablishing communication between the wellbore and the zone of interestvia the fracturing ports. Data from the movement sensors can be used toconfirm that the sleeve was indeed shifted to the open position i.e. asudden downhole acceleration and deceleration of the BHA.

With reference to FIG. 3B, after confirming that the sleeve has beenopened, the packer of the fracturing tool can be set below thefracturing ports of the sleeve sub to isolate the portion of thewellbore above the fracturing tool from the portion of the wellboretherebelow, and fracturing fluid can be introduced into the wellbore tofracture the formation at the zone of interest. Fracturing fluid can beintroduced into the wellbore either through the CT or the annulus, orboth, to stimulate the zone of interest. In CT frac operations,fracturing fluid flows through the tubing bore and out of the ports ofthe BHA and the fracturing ports of the corresponding sleeve valve toreach the zone of interest. In annular frac operations, fracturing fluidflows through the annulus and out of the fracturing ports of thecorresponding sleeve valve to reach the zone of interest. The fluid isprevented from flowing further down the annulus by deploying the packerof the fracturing tool below the fracturing ports of the sleeve valve.In embodiments, a bypass valve of the fracturing tool is also closed toprevent fluid from flowing downhole of the fracturing tool through theaxial bore of the BHA. The sensors of the BHA can be used to confirmsuccessful isolation of the wellbore, for example by comparing themeasurements of a first pressure sensor uphole of the fracturing toolwith the measurements of a second pressure sensor downhole of thefracturing tool. Pressure sensors located in the tubing bore and annuluscan be used during the pumping of fluid into the wellbore to evaluatethe status of the frac. For example, an increase in annular or tubingpressure may indicate a screenout, and a rising differential pressurebetween the tubing bore and annulus may indicate a need to adjust fluidflow.

Once the zone of interest has been fractured, injection of fracturingfluid can cease. In embodiments, for annular fracturing operations,clean fluid can be reverse circulated, that is, injected into the CT toflow out of the flow ports of the BHA and back to surface through theannulus to remove debris. Such reverse circulation can be done in thecase of CT fracturing operations as well if the check valve is notpresent in the BHA, or if the check valve can be actuated to an openposition to permit fluid to flow up the CT through the instrumentationsub. In the case of reverse circulation in CT fracturing operations,care must be taken to avoid screenout of the instrumentation sub due tosand and debris entrained in the circulating fluid.

The BHA is then repositioned by actuating the fracturing tool to thepull-out-of-hole position POOH and pulling on the CT to position the BHAadjacent the next sleeve valve of interest, uphole from the previouslycompleted zone. Once again, the mechanical fracturing tool can beactuated to the sleeve locating position LOC and the BHA moved axiallyuphole until the sleeve valve corresponding to the new zone of interestis located. Once again, the sensors of the BHA can be used to provideinformation with respect to whether the fracturing tool has successfullylocated a sleeve. Once successful location of the sleeve has beenconfirmed, the fracturing tool can be actuated to the sleeve engagingposition SET and the BHA moved downhole to shift the sleeve to the openposition.

In embodiments, the BHA can also be used to close sleeve valves bylocating sleeve valves of interest in the manner described above, andusing the BHA to shift the sleeves of said sleeve valves to the closedposition. The sensors of the BHA can be used to confirm successfullocation and actuation of the sleeve valves to the closed position, forexample by detecting the sudden acceleration and deceleration of theBHA, or a change in axial load on the CT and BHA.

The embodiments in which an exclusive property or privilege is claimedare defined as follows:
 1. A bottom hole assembly (BHA) adapted forconnection to coiled tubing extending from surface into a wellbore, thecoiled tubing having a tubing bore, the BHA comprising: aninstrumentation sub in electrical communication with the surface andhaving a data processor, an axial bore in communication with the tubingbore, and an electrical conduit permitting electrical power and signalsto pass from a first end of the instrumentation sub to a second end ofthe instrumentation sub downhole of the first end; one or more sensorselectrically connected to the instrumentation sub; and a mechanicalshifting tool downhole of the instrumentation sub and adapted foractuating sleeve valves located along the wellbore; wherein the dataprocessor is adapted to receive data from the one or more sensors andcommunicate the data to the surface; and wherein the axial bore is sizedto permit a fluid flow rate conducive to hydraulic fracturingoperations.
 2. The bottom hole assembly of claim 1, wherein the one ormore sensors comprise at least one of a 3D directional sensor, a sensoradapted to determine axial movement, a sensor adapted to determinerotational movement, an axial force sensor, an accelerometer, apositional sensor, a pressure sensor, a temperature sensor, or acombination thereof.
 3. The bottom hole assembly of claim 1, furthercomprising a receiver located uphole of the shifting tool and atransmitter located downhole of the shifting tool, wherein thetransmitter is electrically connected to one or more electricalcomponents located downhole of the shifting tool and the receiver iselectrically connected to the data processor, and wherein thetransmitter is adapted to communicate data to the receiver.
 4. Thebottom hole assembly of claim 3, wherein the receiver is a firsttransceiver, and the transmitter is a second transceiver.
 5. The bottomhole assembly of claim 2, wherein at least one of the one or moresensors is located downhole of the shifting tool and electricallyconnected to the transmitter.
 6. The bottom hole assembly of claim 3,wherein at least a first pressure sensor is located uphole of theshifting tool and at least a second pressure sensor is located downholeof the shifting tool and electrically connected to the transmitter. 7.The bottom hole assembly of claim 1, further comprising a check valvelocated in-line with the axial bore and adapted to prevent fluid fromflowing uphole therethrough.
 8. The bottom hole assembly of claim 1,wherein the fluid flow rate is about 1 m³/min or greater.
 9. The bottomhole assembly of claim 1, further comprising a power source and memorymodule located on the instrumentation sub and electrically connected tothe one or more sensors.
 10. The bottom hole assembly of claim 1,wherein the shifting tool is configured to actuate between variousoperational modes via an axial telescopic movement of a mandrel of theshifting tool relative to a housing of the shifting tool.
 11. The bottomhole assembly of claim 1, further comprising a disconnect locatedbetween the instrumentation sub and the shifting tool.
 12. The bottomhole assembly of claim 11, wherein the disconnect is configured to severan electrical and mechanical connection between the instrumentation suband shifting tool in response to an electrical signal.
 13. The bottomhole assembly of claim 11, wherein the disconnect is configured to severan electrical and mechanical connection between the instrumentation suband shifting tool in response to an actuating member engaging thedisconnect.
 14. The bottom hole assembly of claim 1, wherein thediameter of the axial bore is substantially uniform.
 15. The bottom holeassembly of claim 1, further comprising a drilling tool adapted to beinterchangeable with the shifting tool.
 16. A method for performingfracturing operations in a wellbore having one or more sleeve valvespositioned therealong, comprising: running a bottom hole assembly (BHA)located on a tubing string to a position adjacent a sleeve valve ofinterest of the one or more sleeve valves; pulling uphole on the BHA tolocate the sleeve valve of interest using a mechanical shifting tool ofthe BHA; acquiring data regarding one or more parameters of the BHA andwellbore using one or more sensors electrically connected to aninstrumentation sub of the BHA; actuating the sleeve valve of interestto an open position with the shifting tool; isolating the wellbore belowthe sleeve valve of interest with a packer of the BHA; and introducingfluid into the wellbore to fracture a zone of interest of the wellboreadjacent the sleeve valve of interest.
 17. The method of claim 16,further comprising confirming the successful locating of the sleevevalve of interest using the acquired data, and confirming the successfulactuation of the sleeve valve of interest to the open position using theacquired data, wherein the acquired data comprises at least one ofaccelerometer data and axial load data.
 18. The method of claim 16,further comprising confirming the successful isolation of the wellborebelow the sleeve valve of interest using the acquired data, and whereinthe acquired data comprises at least a first pressure measurement upholeof the shifting tool and a second pressure measurement downhole of theshifting tool.
 19. The method of claim 18, wherein the step of acquiringdata further comprises acquiring the second pressure measurement using apressure sensor downhole of the shifting tool, receiving the secondpressure measurement at a transmitter downhole of the shifting tool, andwirelessly sending the second pressure measurement to a receiver upholeof the shifting tool.
 20. The method of claim 16, wherein the acquireddata comprises data regarding pressure within an axial bore of the BHAand pressure within an annulus defined between the BHA and the wellbore,and the step of introducing fluid further comprises monitoring thepressure in the axial bore and the pressure in the annulus.